This invention relates to an improved method for using biomass and fossil fuels, such as coal, in order to power gas turbine engines using unmixed combustion of solid fuels. The invention also relates to a process for separating the products of unmixed combustion, including pollutants such as carbon dioxide, sulfur compounds, nitrogen compounds, and volatile metals (e.g., mercury) into a separate stream available for subsequent treatment and ultimate sequestration.
One of the major problems in modern industrial society is the production of air pollution by conventional combustion systems based on biomass and fossil fuels. The oldest recognized air pollution problem is the emission of smoke. In modern boilers and furnaces, smoke emissions could be eliminated or at least greatly reduced by the use of Over Fire Air (xe2x80x9cOFAxe2x80x9d) technology. Other types of air pollution produced by combustion include particulate emissions such as fine particles of ash from pulverized coal firing, oxides of sulfur (SO2 and SO3), carbon monoxide emissions, volatile hydrocarbon emissions and the release of two oxides of nitrogen, NO and NO2. More recently, the problem of global warming due to greenhouse gas emissions of CO2 from power plants and other combustion systems have become a matter of serious environmental concern.
Another major technological problem concerns the use of coal as a fuel for powering gas turbines. Gas turbines are the lowest capital cost systems available for generating electrical power. Since the thermodynamic efficiency of gas turbines increases with increasing turbine inlet temperature, efforts to improve turbine efficiency generally involve increasing the turbine inlet temperature to higher levels. As a result, turbine blades and other components have been engineered to tolerate increasing high inlet temperatures.
It is well known that the hot gases produced by coal firing contain fly ash (which is erosive to turbine blades). In the presence of this erosive fly ash the maximum service temperature at which turbine blades can operate is less than it would be otherwise. This limitation significantly decreases the overall process efficiency and lowers the competitiveness of coal as a gas turbine fuel. These and other disadvantages have also prevented lower cost (and abundant) coal from being considered an attractive gas turbine fuel. If a process were developed whereby coal could be burned in a manner that produced hot gases that were not erosive or corrosive, the need for temperature reduction would be eliminated and coal would become a much more economically viable gas turbine fuel.
With respect to global warming, coal has the further disadvantage that its CO2 emissions per BTU released are significantly higher than those of most ashfree fuels. Again, however, if coal could be burned in a manner that did not cause the emission of CO2 and/or other pollutants, this known disadvantage would disappear, making coal a much more environmentally acceptable fuel for existing uses and new uses such as fueling gas turbines.
U.S. Pat. Nos. 5,339,754, 5,509,362 and 5,827,496 (incorporated herein by reference) disclose a new method of burning fuels using a catalyst that is readily reduced when in an oxidized state and readily oxidized when in a reduced state, with the fuel and air being alternatively contacted with the catalyst. The fuel reduces the catalyst and is oxidized to CO2 and water vapor. In turn, the air oxidizes the catalyst and becomes depleted of oxygen. Combustion can thereby be effected without the need of mixing the fuel and air prior to or during the combustion process. If means are provided whereby the CO2 and water vapor and the oxygen depleted air can be directed in different directions as they leave the combustion process, the mixing of fuel and air can be completely avoided. This particular method of combustion has become known in the art as xe2x80x9cunmixed combustion.xe2x80x9d In one embodiment disclosed in the ""362 patent, the CO2 produced by the combustion process is separated from the water vapor and disposed of by conventional means. The ""362 patent also removes the acid gases such as SO2, HCl and HF.
It is well known that the total volume of combustion gases produced by unmixed combustion is comparable to that produced in conventional combustion. It is also well known that the cost of removing acid gases from combustion effluents by scrubbing increases with the volume of gas being scrubbed. The ""362 patent recognize that if unmixed combustion is carefully controlled such that the acid gases leave the combustion process as part of the CO2 and water vapor steam, the volume of gas that must be scrubbed can be greatly reduced, as well as the cost of scrubbing.
The subject matter of the ""362 patent is discussed in greater detail in paper 98F36, presented at the October 1998 meeting of the Western States Section of the Combustion Institute (hereafter referred to as the xe2x80x9cCombustion Institute paperxe2x80x9d). The authors of the paper include R. K. Lyon (the inventor of U.S. Pat. No. 5,509,362 and the inventor of the present invention) and J. A. Cole. The paper discloses a conceptual process for using coal to power a gas turbine and reports on a series of experiments illustrating certain aspects of the proposed process.
The reported experiments used an atmospheric pressure fluid bed of powdered, chemically pure iron oxide (i.e., FeO/Fe2O3). In the experimental setup, the gas being used to fluidize the bed could be switched from air to 5% SO2+95% N2 and back again. The basic experiments as reported in the paper involved two steps. First, a bed fully oxidized to Fe2O3 was fluidized with the 5% SO2+95% N2 at a temperature of 857 @ C. A small amount of coal was injected into the bed while the gases leaving the bed were continuously analyzed. In a second step, the fluidizing gas was switched to air while the gases leaving the bed were analyzed. Based on available data, the paper concludes that coal is readily oxidized in the presence of SO2 and that the chief carbon containing product of the oxidation is CO2, with little or no CO being produced. The paper attributes the ability of the solid particles of Fe2O3 to rapidly oxidize the coal to a catalytic action by the SO2 used in the fluidizing gas. That is, the SO2 reacts with the coal, converting it into to CO2, CO, CS2, COS, and sulfur vapor. The CO, CS2, COS, and sulfur vapor are, in turn, oxidized by the Fe2O3 to CO2 and SO2. Thus, the SO2 serves as a catalyst, allowing the solid Fe2O3 to oxidize the solid coal char. The first half of this process, the gasification of coal char by SO2, is described by J. D. Blackwood and D. J. McCarthy in the Australian J. Chem. P. 723, 1973.
The initial experiments reported in the Combustion Institute paper indicate that the gases exiting the bed after being fluidized with air contain little or no SO2 and little or no CO and CO2. Thus, the paper concludes that the Fe2O3 oxidized the coal to completion during the first step, i.e., while the bed was fluidized with 5% SO2+95% N2. The oxidation converted all the sulfur in the coal to SO2 and other volatile species which exited the bed during the first step of the experiment.
Another series of two-step experiments discussed in the paper used a bed fluidized with N2. Like the experiments conducted with coal, when the amount of thiophene injected was small, all of the sulfur left the bed as SO2 and other volatile species during the first step. Conversely, none of the sulfur was retained in the bed during the first step and exited during the second air fluidization step. Increasing the amount of injected thiophene changed that situation. That is, injecting thiophene in excess of a threshold amount caused some of the sulfur to be retained in the bed during the first step and to be released as SO2 during the second air fluidization step. The paper speculates that this threshold is a result of FeS, i.e., after thiophene reduces some of the Fe2O3 to FeO, injection of more thiophene causes the formation of FeS. Once formed, the FeS remains during the first step and then oxidizes to Fe2O3 and SO2 during the air fluidization step.
Based on these experimental observations, the Combustion Institute paper then proposes a conceptual design for a process to use coal to power a gas turbine. As shown in The reference""s FIG. 4, the Fe2O3 catalyst in fluidized powder form circulates between a first fluid bed fluidized with steam and a second bed fluidized with air. FIG. 4 shows the transfer lines between two fluid beds as being purged with steam. The second fluid bed is fluidized with compressed air from the compressor section of a gas turbine. With this bed, FeO is oxidized to Fe2O3, a strongly exothermic reaction that depletes the compressed air of oxygen and heats it. The heated compressed air is then used to drive the expander section of the gas turbine.
The Combustion Institute paper contemplates feeding pulverized coal to the first steam fluidized bed where it reduces the Fe2O3 to FeO while being oxidized to CO2, water vapor, and fly ash. All the volatile products of combustion are swept from the bed. The fluidization conditions in the bed are such that the fly ash is rapidly removed from the bed by elutriation. FIG. 4 calls for the fly ash to be removed from the other combustion products with a cyclone separator after which the ash goes to disposal. Once heat is recovered from the remaining combustion products, water vapor is removed by condensation and the resultant CO2 and SO2 mixture is disposed of.
The Combustion Institute paper concludes that the conditions under which the coal is oxidized are such that all or virtually all of the sulfur in the coal is converted to SO2 and other volatile species rather than reacting with the FeO/Fe2O3 to form FeS or other nonvolatile sulfur containing species. Obviously, the formation of FeS and similar species is undesirable from an environmental standpoint. Instead of being swept out of the steam fluidized bed, they tend to circulate into the air fluidized bed where they oxidize to SO2 and cause the emission of air pollutants.
Three final aspects of the Combustion Institute paper should also be noted. First, the paper teaches that if the conversion of Fe2O3 to FeO is kept below a certain threshold, FeS is not formed and SO2 emissions are avoided. Although the paper notes the amount of thiophene needed to exceed this threshold for the amount of Fe2O3 used in the experiment, it is silent as to how much Fe2O3 was used. Thus the paper does not identify the extent of Fe2O3 conversion at which the threshold occurs. Nor does it explain how a change in temperature effects the threshold or how catalyst aging changes the threshold. The paper also fails to disclose how the threshold would be effected by changing the form in which the Fe2O3 is used, e.g., replacing chemically pure Fe2O3 with iron ore, red mud (a byproduct of aluminum production with a high iron content) or other low cost iron containing products.
With respect to the problem of achieving complete combustion of the coal, the Combustion Institute paper teaches that 5% SO2 as used in the paper""s experiment corresponds to the concentration of SO2 produced in the proposed process, i.e., the concentration of SO2 in moles per liter which would be produced by oxidation of high sulfur Illinois coal with Fe2O3 at a sufficiently elevated pressure. For lower sulfur coals, the concentration of SO2 will be lower, making the coal oxidation rate unacceptably low. The only solution suggested for this problem is very expensive, namely raising the SO2 concentration by recycling SO2, i.e., by recovering SO2 from the recovered SO2+CO2 mixture and returning it to the first fluid bed.
It is well known that efficient coal combustion requires that the carbon content of the fly ash be low. The Combustion Institute paper""s experiments show that coal can be rapidly oxidized to CO2, water vapor and xe2x80x9cfly ash.xe2x80x9d However, a coal particle becomes xe2x80x9cfly ashxe2x80x9d when oxidation shrinks it to the point that it flies out of the fluid bed. While this implies that the xe2x80x9cfly ashxe2x80x9d would have a substantial carbon content, the paper does not identify the carbon content of the fly ash. The reference""s FIG. 4 contemplates removing fly ash from the gases leaving the first fluid bed with a cyclone and sending this fly ash to disposal. However, this would mean discarding a significant fraction of the coal""s heat of combustion.
It is also known that the theoretical maximum possible efficiency of a gas turbine increases with increasing turbine inlet temperature. Thus, if a gas turbine is to operate with an acceptably high efficiency, the inlet temperature should be at temperatures approaching 1500xc2x0 C. For the conceptual process shown in The reference""s FIG. 4, the turbine inlet temperature would be the same or slightly less than the temperature at which the second fluid bed operates. On page 10, the paper teaches that the first fluid bed is to be operated at a temperature of 700xc2x0 C.-900xc2x0 C. Within the framework of the reference""s FIG. 4 conceptual process, this teaching is necessary since the first fluid bed must be operated at a temperature below the coal""s ash fusion temperature.
The Combustion Institute paper teaches that the second fluid bed should be operated at a temperature of xe2x80x9cnearly 1500xc2x0 C.xe2x80x9d This teaching is necessary if the gas turbine is to operate with satisfactory efficiency and implies a temperature increase of 600xc2x0 C. to 800xc2x0 C. In order to provide this temperature increase, the paper teaches that the ratio of coal to Fe2O3 feed to the first bed be sufficient so that 60% of the Fe2O3 is reduced to FeO. One can readily calculate that if a stoichiometric quantity of air is preheated to 400xc2x0 C. and reacts adiabatically with Fe2O3 60% of which has been reduced to FeO, the final temperature will be 1495.2xc2x0 C.
However, important limitations exist with respect to the catalyst under such conditions. The threshold for FeS formation must be 60% conversion or greater if SO2 emissions are to be avoided. The catalyst must consist almost entirely of Fe2O3/FeO, i.e., if the catalyst contained any substantial amount of inert material, the added heat capacity of this inert material would reduce the temperature increase. The Combustion Institute paper thus requires the use of pure or nearly pure Fe2 O3/FeO, a relatively expensive material, rather than much less expensive iron ore or red mud. Furthermore, aging of the expensive Fe2O3/FeO catalyst effectively converts it into an inert heat capacity. Thus, the teachings of the paper imply that the catalyst life will be short since relatively little catalyst aging can be tolerated. The paper also confirms the disadvantage in having sulfur in the coal recovered as SO2. There is virtually no market for sulfur as SO2 and its storage and disposal can be expensive and difficult. In contrast, elemental sulfur is readily shipped and has a substantial market potential. Moreover, in situations in which it cannot be sold, the storage and/or disposal of sulfur is relatively easy and inexpensive.
Thus, despite recent developments in the art, a significant need still exists in the art for a new method of burning coal to power gas turbines that will avoid the limitations discussed above with respect to the unmixed combustion of solid fuels such as coal.
The present invention provides an improved method of burning coal to power gas turbines, and achieves high efficiency while controlling SO2, CO2, Hg and NOx emissions. The invention also provides an improved method of burning coal as compared to the prior art (including the Combustion Institute paper) that allows the use of catalysts other than high purity Fe2O3/FeO (i.e., iron oxides with a significant fraction becoming inert due to aging and in mixture with inert noncatalytic materials). The invention also provides a method of efficiently separating all the pollutants, including CO2, sulfur compounds, nitrogen compounds, and volatile metals, such as mercury, into a separate stream for downstream treatment or disposal.